1. Field of Invention
The present invention relates generally to the field of well servicing of oil and gas wells, and more particularly to methods and systems useful in well servicing operations such as well stimulation.
2. Related Art
The production of hydrocarbon from reservoirs requires permanently installed wellbores in the ground composed of a multiplicity of largely tubular structures referred to as the wellbore completion. Increasing the production of hydrocarbon typically requires the pumping of a fluid down the wellbore and into the reservoir. Some fluids are designed to increase the flow of hydrocarbon, others impede the flow of water or build-up of scale. Measurements may be made of fluid flow-rate, pressure, etc, at the surface to optimize the treatment. This monitoring operation is non-trivial, however, because the fluids are typically highly non-Newtonian with pressure-drops along the completion that are difficult to determine in advance. The stimulation fluid may include solid particles, such as proppant, which further complicates the monitoring and job optimization.
Solutions to provide a more advanced monitoring capability are known in the industry. For example, a spoolable metallic tube may be run into the well, with the stimulation fluid pumped around that tube. In that case the downhole pressure may be inferred from a pressure measurement made in the interior of the tube. With no fluid flowing down the tube, this inference is relatively simple. Such a tube is often referred to as a “dead-string”. Spoolable tubes known in the industry are typically brought to the rig already coiled around a drum that is mounted onto a large truck. This coiled tubing may vary from 0.25″ to bigger than 3.0″ in diameter. An advantage of the larger size tubing is that cable may be pumped into that coiled tubing before the job, sensors may be attached to the distal end of that cable, and then when the coiled tubing is run into the ground, those sensors may transmit downhole data to the surface. Another advantage of the larger tubing is that it may be possible to pump fluid down the tubing even with the cable in the tubing. Such a system need not be limited to reservoir stimulation but may be used for general wellbore treatments as has been disclosed in, for example, U.S. Pub. Pat. App. No. 20050126777, published Jun. 16, 2005. Traditional cables used in the industry consist of a multiplicity of electrical lines, but more recently optical fibers have been added. These provide higher data rates, but also introduce the possibility of distributed sensing, wherein the cable itself becomes the sensor. Such a system has been disclosed, for example, in U.S. Pub. Pat. App. No. 20040129418, published Jul. 8, 2004.
Unfortunately, there may be disadvantages to having the coiled tubing in the wellbore during the stimulation treatment. The annular space around the tubing may be less than one or two inches, which increases the friction pressure when the fluid is pumped and so increases the surface horsepower required to do the job, compared with pumping straight into the wellbore—a process known as bull-heading. Abrasive and corrosive fluids are often needed to optimize the subsequent hydrocarbon flow. These fluids may also damage the coiled tubing leading to high maintenance costs for the service. Another disadvantage is the large apparatus needed to convey the coiled tubing into the wellbore such as disclosed, for example in U.S. Pat. No. 6,273,188. In particular, to avoid crushing the coiled tubing, a large injection apparatus is required to provide the axial conveyance force into, and out of, the wellbore as disclosed, for example, in U.S. Pat. No. 4,585,061 “Apparatus for inserting and withdrawing coiled tubing with respect to a well” by Lyons et al. In many cases, the cost of such systems may be prohibitive compared to the benefit of the real-time downhole data, so the industry has come to accept taking surface measurements and making inferences of the downhole state.
U.S. Pub. Pat. App. No. 20050263281, published Dec. 1, 2005, discloses applications of real-time downhole data to stimulation operations, but presupposes that the optical fiber is first contained inside a tubular, and the tubular then run into the well. U.S. Pub. Pat. App. No. 20050236161, published Oct. 27, 2005, discloses pumping a fluid into a tubular and deploying a fiber optic tube into the tubular by propelling it in the flow of the pumped fluid. This document also discusses a method of communicating in a wellbore using a fiber optic tube disposed within a wellbore tubular. In certain embodiments, this communication may be combined with a wireless communication system at the surface. In certain embodiments, the tubular may be coiled tubing and the fiber optic tube may be deployed in the coiled tubing while the tubing is spooled on a reel or while the tubing is deployed in a wellbore. As used in this reference the phrases “fiber optic tube” and “fiber optic tether” are used to identify the combination of an optical fiber or multiple optical fibers disposed in a duct. The term “fiber optic cable” refers to a cable, wire, wireline or slickline that comprises one or more optical fibers.
It would be a revolutionary advance in the art if methods and systems could be devised that allow collection of downhole data during a stimulation or other wellbore treatment operation, but which do not require ancillary apparatus to inject or remove coiled tubing or other tubular from the wellbore.